What CRE Pays for Speed to Power
A CBRE guidebook provides cost and timing benchmarks, but the test is whether onsite generation can protect a project's value and for how long.
Speed to power has become a real estate test. When a property cannot secure electricity on a tenant’s schedule, its ability to open, collect rent and support its intended use may be at risk.
The issue is most visible in data centers, where access to power can outweigh location in site selection. But it is increasingly shaping decisions for advanced manufacturing and other power-sensitive industrial uses, affecting rents, site feasibility and investment decisions.
CBRE Energy has worked on sites where the utility’s original timetable put the required capacity in the early 2030s. By adding onsite resources to cover periods of grid constraint, those projects could begin operating sooner, with limited grip supply supplemented by generation at the property.
“Sites that did not work on the original utility timeline then became viable against the end tenant’s or owner’s timing requirements,” said Pol Lezcano, director of market intelligence with CBRE Energy and a co-author of CBRE’s Distributed Generation Guidebook. “Through a ramp-up where only limited grid supply is available, onsite generation lifts the peak power capacity that the site can actually run at. In some cases, it roughly doubles what the site could do on grid supply alone.”
CBRE’s guidebook estimates that the average U.S. customer lost power for 11 hours in 2024, while 20 percent of data center operators said their most recent outage cost more than $1 million. For real estate owners, the exposure can also include carrying costs, deferred rent and the loss of a tenant.
The cost of speed to power
The cost of onsite power varies by technology and project conditions. CBRE estimates that a new diesel backup generator requires $300 to $700 per kilowatt of capital, compared with $700 to $1,500 per kilowatt for a natural gas unit. But those ranges alone do not determine which system will work best. Fuel storage, pipeline access, permitting and allowable run time all affect what a system can deliver at a particular site.
The premium for faster deployment can be larger across technology types, especially in the power-first data center market, where developers increasingly follow available megawatts rather than wait for conventional infrastructure expansion.
“On the arithmetic, mobile turbines run from $230 to $400 per megawatt-hour against $55 to $90 per megawatt-hour for permanent gas, and they arrive eight to 26 months sooner,” Lezcano said. “The two numbers only give part of the story. The levelized numbers assume 20 years of operation, so they do not map onto equipment you intend to return. For bridge power, the monthly rate of $150 to $250 per kilowatt-month plus fuel costs is often more helpful.”
For an owner, the relevant calculation weighs the cost of bridge power against the carrying costs it could reduce, the rent it could bring forward and the value of meeting a contractual delivery milestone or retaining a tenant. A specialized manufacturer may also find the premium worthwhile if a grid constraint would prevent it from reaching full utilization during a seasonal production peak.
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“The economics get misread as a comparison between the cost of onsite power and the cost of grid power. That is only one part of the equation,” said Sy Kim, vice president with CBRE Energy and guidebook co-author. “There’s also the economic loss from under-production, or from having to shut down operations, revamp and restart an entire line or facility.”
A low utility tariff is therefore only one part of the benchmark. The investment case depends on whether the cost of the reliability solution is outweighed by the losses it prevents. At a leased property, the underwriting also needs to show which party captures those savings.
Why project costs, timelines vary
CBRE’s cost estimates provide a starting point, but they are not project quotes, according to Kim. The estimates assume two decades of operation with the equipment running at an average of 90 percent of maximum output, a natural gas price of $4 per million British thermal units and an 8 percent cost of capital.
“Change any one of those inputs and the answer changes with it,” Kim added. “We regularly see this in our work reviewing developer submissions, where each proposal has built in its own set of assumptions for the same site.”
Site-specific conditions can add costs and affect what’s feasible. Physical constraints, local air rules, environmental review and utility participation all shape development and construction. A gas engine cannot operate until the utility builds the lateral or gas connection to the site. A battery faces fire-code and interconnection reviews. Also, equipment availability can matter as much as its listed price.
Operations and maintenance are also easy to understate. “Some turbines need highly specialized maintenance, the cost for which can vary widely,” Kim said. “These assets require fuel inputs over the life of the project, so companies need to account for fuel forward curves.” Those curves reflect market prices for future fuel deliveries. “The premium to secure a hedge on fuel inputs, which can fix fuel costs, is rarely factored in,” he added.
The deployment estimates have a similar limitation. “The timelines in the report start at contract execution because what comes before varies too much by project to put a range on. It is often the longer phase,” Lezcano said.
But before a contract is signed, engineering, finance, tax, legal and facilities teams need to agree on the project, its contract structure and how its costs and benefits will be allocated. This coordination matters as power and automation reshape industrial facility requirements and investment criteria. After signing, the owner still depends on factors outside their control, including gas utility construction, local air permitting, electric interconnection review, supply-chain conditions and equipment lead times.
Who pays and who benefits
The generator may sit at the property, but its economic value does not automatically accrue to the landlord. Earlier occupancy, operating savings, avoided downtime, higher rent, a longer lease and the ability to compete for a power-sensitive tenant are distinct potential benefits. The lease and power contracts determine which party receives each one.
“In a standard triple net-leased facility where the site owner finances the onsite power, tenants are often willing to pay a premium for a site with power availability and/or reliability,” Kim said. “For the site owner, this translates to higher rents or a longer-term contract, while the tenant realizes energy savings.”
The allocation changes with other lease structures. A landlord paying for generation at a full-service or modified-gross property may capture the energy savings directly. If an industrial tenant finances the system, the tenant typically receives the operating savings and protection from lost output or equipment damage. The underwriting should specify who pays and who benefits in each case.
Third-party financing can align the costs and benefits, said Kim. “Both the tenant and the landlord benefit from avoiding capital expenditures and ongoing non-core operating costs, while realizing energy cost savings or reliability value, in exchange for sharing that value with the developer.”
The developer may retain a portion of the savings or receive a minimum payment set below the cost of grid power. Ownership also affects who can use available tax credits and how the project enters the capital stack, making incentive eligibility and tax treatment part of the underwriting.
The bridge needs an exit
The base case should account for grid power eventually costing less than onsite generation. But a promised connection date does not guarantee firm, sufficient service. Owners need to model capacity, congestion charges and unfinished system upgrades to determine whether bridge generation should be removed, retained as backup or replaced with a cheaper permanent onsite system.
“Most bridge power is rental equipment installed to cover a delayed utility service date,” Lezcano said. “The vendor runs its own inventory and customer pipeline and will reallocate that unit when the term ends. So, the contract has to be specific about term length and about the extension clauses, for the case where utility service arrives later than expected or arrives with less capacity than modeled.”
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Owned equipment presents different choices. It can remain as emergency backup, although permits typically cap operation to roughly 50 to 100 hours annually, or it can be redeployed or sold. A temporary system may also become permanent if the eventual grid connection remains constrained. In that case, what began as schedule insurance turns into a longer-term commitment to fuel, maintenance, permitting and emissions costs.
“For many companies with a climate commitment, electrification is the most direct path, and using battery storage as far as it will go for back-up reliability and savings can be the simplest long-term option,” Lezcano said. Batteries, however, generally cover only short-duration needs. Gas can provide firm power but adds fuel and infrastructure risk, while lower-carbon replacement fuels still carry a significant premium and uncertain future availability.
For a grid-constrained property, the power plan needs to enter acquisition, development and leasing decisions early enough to be underwritten. Speed to power can make a site viable, but the investment still depends on realistic assumptions about cost, value allocation, delivery risk or the eventual exit from the bridge.
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